1. Field of the Invention
This invention relates to the recovery of hydrocarbons from a natural gas stream and further relates to separating ethane and higher boiling hydrocarbons from the methane in a natural gas stream. It more specifically relates to supplying specific market needs for hydrocarbons by selective recovery of ethane, propane, or ethane plus propane from a stream of lower molecular weight hydrocarbons that have been selectively rejected from a stream of C.sub.2 + hydrocarbons recovered from a natural gas stream.
2. Review of the Prior Art
Numerous processes have been used to extract liquids from natural gas streams. These processes include oil absorption, refrigerated oil absorption, simple refrigeration, cascaded refrigeration, Joule-Thompson expansion, and cryogenic turbo-expansion.
In summary, the oil absorption, refrigerated oil absorption, simple refrigeration, and cascaded refrigeration processes operate at the pipeline pressures, without letting down the gas pressure, but the recovery of desirable liquids (ethane plus heavier components) is quite poor, with the exception of the cascaded refrigeration process which has extremely high operating costs but achieves good ethane and propane recoveries. The Joule-Thompson and cryogenic expander processes achieve high ethane recoveries by letting down the pressure of the entire inlet gas, which is primarily methane (typically 80-85%), but recompression of most of the inlet gas is quite expensive.
In all of the above processes, the ethane plus heavier components are recovered in a specific configuration determined by their composition in the raw natural gas stream and by equilibrium at the key operating conditions of pressure and temperature within the process. Flexibility of recovery, independently of such composition and equilibrium, is not possible.
Under poor economic conditions when, for example, ethane price as petrochemical feedstock is less than its equivalent fuel price and when the propane price for feedstock usage is attractive, the operator of a natural gas liquid extraction plant is consequently limited as to operating choice because he is unable to minimize ethane recovery and maximize propane recovery in response to market conditions.
The refrigeration process which typically recovers 80% of the propane also typically requires the recovery of 35% of the ethane. In order to boost propane recovery to the 95+% level, cascaded refrigeration, Joule-Thompson, or cryogenic turbo expander processes would have to be used while simultaneously boosting the ethane recovery to 70+% at a considerably larger capital investment.
Similarly, when the ethane price as petrochemical feedstock is greater than its fuel value while propane price as propane feedstock is unattractive, none of the above-mentioned processes allow an operator to selectively recover ethane while rejecting propane.
Extraction processes are available that employ liquids other than hydrocarbon oils for removal of acidic components, including H.sub.2 S and CO.sub.2, and water. These liquids comprise propylene carbonate, N-methyl pyrrolidone, glycerol triacetate, polyethyleneglycol dimethyl ether (DMPEG), triethylolamine, tributyl phosphate, and gamma butyrolacetone.
U.S. Pat. Nos. 3,362,133, 3,770,622, 3,837,143, 4,052,176, and 4,070,165 teach various prior art processes for extracting acidic components, heavier hydrocarbons, or water from natural gas streams.
As presented at the 50th Annual Gas Processors Association Convention, Mar. 17-19, 1980, in a paper entitled "High CO.sub.2 --High H.sub.2 S Removal with SELEXOL Solvent" by John W. Sweny, the relative solubility in DMPEG of CO.sub.2 over methane is 15.0 while that of propane is 15.3. The relative solubility in DMPEG of H.sub.2 S over methane is 134 versus 165 for hexane in DMPEG. The relative solubilities in DMPEG of iso and normal butanes and of iso and normal pentanes are in between those of propane and H.sub.2 S. These data indicate that if CO.sub.2 and H.sub.2 S are present in a natural gas stream which contains C.sub.2 + heavier hydrocarbons that are desirable for petrochemical industry feedstocks, substantial quantities of C.sub.2 + hydrocarbons will be lost with CO.sub.2 and H.sub.2 S vent streams when a sour natural gas stream is treated with DMPEG.
Sweet natural gas is usually saturated with water at its ambient temperature which may have a range of 75.degree.-120.degree. F., so that its water content may vary from 20 pounds to more than 50 pounds per million standard cubic feet. However, difficulties are frequently met while pumping such natural gas unless the water content is reduced to a value of less than 12 pounds, preferably less than 7 pounds, of water per million standard cubic feet of natural gas. In terms of dew point, a natural gas having a dew point of 30.degree. F., preferably 20.degree. F. or lower, is generally considered safe for transportation in a pipeline. Dehydration can be carried out under a wide range of pressures from 15 to 5000 psig, but it is usually carried out at pipeline pressures of 500-1500 psig and generally near 1000 psig.
There has nevertheless existed a need for a process wherein C.sub.2 + hydrocarbons and water could be simultaneously removed to any selected degree without also extracting hydrocarbons of lower molecular weight, such as methane.
There has additionally existed a need for a process wherein any natural gas, from very sour to entirely sweet, could be handled by the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons.
These needs have been met by the process described in the parent application, Ser. No. 06/507,564, filed June 24, 1983, which is fully incorporated herein by reference. This process produces a liquid hydrocarbon product having a composition which is selectively versatile rather than fixed, as in prior art processes. In consequence, the composition of its hydrocarbon product can be readily adjusted in accordance with market conditions so that profitability of the absorption operation can be maximized at all times and on short notice.
Such versatility is achieved by flexibility in certain operating conditions and by use of certain additional steps that are not used in the prior art. These conditions and steps are listed as follows, in order of importance:
(1) varying the flow rate of the solvent with respect to flow rate of the natural gas stream; PA1 (2) varying the flashing pressure for one or more of the successive flashing stages; PA1 (3) recycling the flashed C.sub.1 + undesirable gases to the extraction column; and PA1 (4) rejecting selected components of the liquid product, viz., methane (demethanizing), methane plus ethane (de-ethanizing), methane, ethane, and propane (depropanizing), or methane, ethane, propane, and butanes (debutanizing) in a stripping column for the liquid product by: PA1 A. selectively removing a stream of hydrocarbons that are primarily heavier than methane from the natural gas stream; PA1 B. selectively rejecting a consecutively lowest molecular weight portion of the extracted stream, this rejected portion comprising, as its heaviest component, the propane or the butanes; PA1 C. selectively removing ethane, propane, or ethane plus propane from the rejected portion; PA1 D. combining the remainder of the rejected portion from Step C with the remainder of the natural gas stream of Steps B and A, the first remainder comprising the propane, the butane, or the propane plus butane, to form the residue natural gas stream, and PA1 E. combining the ethane, the propane, or the ethane plus propane from Step C with the remainder of the extracted stream from Steps A and B to form the liquid hydrocarbon product. PA1 A. extracting the water and the hydrocarbons that are primarily heavier than methane from the natural gas stream with a physical solvent at pipeline pressures and at a solvent flow rate sufficient to produce rich solvent containing the water, a selected C.sub.1 + mixture of hydrocarbons, and the remainder of the natural gas stream; PA1 B. successively flashing the rich solvent in a plurality of flashing stages at successively selected decreasing pressures to produce a plurality of successive C.sub.1 + gas fractions, having successively lower methane contents, and successive liquid mixtures of the water, the solvent, and mixtures of hydrocarbons having successively lower methane contents; and PA1 C. regenerating the liquid mixture from the last stage of the flashing stages to produce the physical solvent for the extracting. PA1 A. selectively varying the solvent flow rate with respect to the flow rate of the natural gas stream during the extracting step to adjust the composition of the rich solvent stream relative to selected components of the group consisting of ethane, propane, iso and normal butanes, and components heavier than butanes; PA1 B. selectively varying the flashing pressures of the successive flashing stages in order to adjust the compositions of the successive gas fractions and of the successive liquid mixtures relative to the selected components; PA1 C. recycling at least the first of the successive flashed C.sub.1 + gas fractions to the extracting step in order to extract maximum quantities of the hydrocarbons heavier than methane; and PA1 D. demethanizing at least the last of the successive C.sub.1 + gas fractions, in order to produce the desired remainder of the extracted stream, by: PA1 A. selectively extracting the rejected portion in the second extracting unit to produce a gas stream, selected from the group consisting of methane and methane plus ethane, and a second rich solvent stream, consisting of the physical solvent and at least two of the highest molecular weight components of the rejected portion; PA1 B. flashing the second rich solvent stream to produce an overhead stream consisting of all extracted hydrocarbon components and a bottom physical solvent stream; and PA1 C. de-ethanizing the overhead stream in the splitter to produce:
(a) varying the pressure in the column, and PA2 (b) varying the temperature at the bottom of the column. PA2 (1) selectively varying the pressure of the demethanizing, and PA2 (2) selectively varying the bottoms temperature of the demethanizing. PA2 (1) the ethane, the propane, or the ethane plus propane as an overhead product stream; and PA2 (2) the propane, the butane, or the propane plus butane as a bottoms stream for combining with the remainder of the natural gas stream to produce the residue natural gas stream.
When an operator is changing process conditions to produce a new liquid product mix in accordance with the needs of the market, he must have all four process steps available for consideration. He must consider each of the steps in the order listed, but he need not necessarily change all of them. For some natural gas streams, solvent flow variation and recycling in addition to demethanizing is adequate, for example. However, for most natural gas streams, optimum efficiency is obtained when all five of the preceding conditions and steps are utilized. It is thereby extremely easy, for example, to recover 99+% of propane and less than 2% of ethane without any additional investment or to recover 99+% of the butanes and less than 2% of the ethane and propane without any additional investment.
"Demethanizing" refers strictly to removal of methane from the liquid product entering the demethanizer. When ethane is additionally removed, such removal may herein be referred to as de-ethanizing; when propane is also removed, such removal may herein be identified as depropanizing; and when butanes are further removed, such removal may herein be described as debutanizing. Nevertheless, the generic term used herein for removal of C.sub.1, C.sub.1 +C.sub.2, C.sub.1 +C.sub.2 +C.sub.3, or C.sub.1 +C.sub.2 +C.sub.3 +C.sub.4 's is demethanizing or stripping, and, unless otherwise qualified, this term is to be understood as encompassing any one of these four removal possibilities.
However, daily changes in market conditions may also cause the price of a single liquid hydrocarbon heavier than ethane to drop below its fuel price so that this hydrocarbon should be selectively rejected, but there is presently no way of doing so without also rejecting all components of lower molecular weight. For example, if the price of ethane is below its fuel value, it can be rejected with the methane, as taught in the parent application, but if the price of propane is below its fuel value while the price of ethane is above its fuel value, no method exists for separating these hydrocarbons.
Therefore, for all components heavier than ethane, there exists a need for selectively rejecting any one or two selected hydrocarbons of consecutive molecular weight that are heavier than another recoverable and desirable hydrocarbon which may include ethane. As a practical matter, such hydrocarbons which need to be selectively rejectable are propane, the butanes, and propane plus the butanes.